Estimation Of Gas In Place Research Articles

Influence of organic matter type on porosity development in the Wufeng-Longmaxi Shale: A combined microscopy, neutron scattering and physisorption approach

The upper Ordovician Wufeng Shale and lower Silurian Longmaxi Shale are part of the Fuling shale gas play located in the south-eastern part of the Sichuan Basin, southern China, representing the first commercial shale gas production project outside North America. We studied the occurrence of porosity at the micro- and nano-scale in samples of contrasting organic richness representing the typical lithofacies from the post-mature part of the Wufeng-Longmaxi gas play. Using a combination of site specific, high-resolution scanning and transmission electron microscopy with bulk measurements based on small angle neutron scattering and cryogenic Argon physisorption, along with conventional organic petrology, we highlight the impact of different types of organic matter (OM) (primary versus secondary) on the development of OM-hosted porosity. The results indicate that at the bulk scale the overall porosity in the samples is proportional to their organic content and organic hosted pore account for 30–40% of the total pore volume of the rocks. Nevertheless, most of the pores identified via electron microscopy imaging seem to reside in the organic matter, indicating that potentially a large part of the pores volume detected by neutron scattering and Argon physisorption is visually not detected. Organic matter focused nanoscale imaging revealed that mesopores are preferentially present in the solid bitumen and not in the primary detrital organic particles. Organic lean samples show low porosity and dominance of micropores, while organic-rich samples show higher porosity and a broader spectrum of pore sizes. Importantly, most of the meso pores are located in organic matter petrographically interpreted as solid bitumen, while detrital organic particles like graptolites show minimal visible porosity under high resolution electron microscopy and pore sizes in the micro pore range (i.e. <2 nm).Distinguishing between primary and secondary OM is therefore important for understanding the creation of an interconnected network of porous OM during hydrocarbon migration. This may have an important control on the estimation of gas in place and the gas transport properties of the shale.

Comparison of the Methods for Analyzing Rate- and Pressure-Transient Data from Multistage Hydraulically Fractured Unconventional Gas Reservoirs

Summary In this study, we provide a detailed review and comparison of the various graphical methods, available in the literature, to interpret/analyze rate- and pressure-transient data acquired from multistage hydraulically fractured horizontal wells (MHFHWs) completed in unconventional gas reservoirs. The methods reviewed in this study do not address complex transport mechanisms and complex fracture networks, but do address transient matrix linear flow (Ibrahim and Wattenbarger 2006; Nobakht and Clarkson 2012a, 2012b; Chen and Raghavan 2013) and boundary-dominated flow (BDF). The methods for BDF are the contacted-volume methods based on the ending times of linear flow (Wattenbarger et al. 1998; Behmanesh et al. 2015) and the flowing material-balance (FMB) methods. The Agarwal-Gardner FMB method (Agarwal et al. 1999) and the conventional FMB method involve plotting rate-normalized pseudopressure vs. material-balance pseudotime. We delineate the advantages and limitations associated with each method and identify the best methods of interpretation and analysis. Three different production modes—constant rate (CR), constant bottomhole pressure (BHP) (CBHP), and variable-rate BHP—are considered. For comparison, various synthetic test data sets generated from a high-resolution spectral gas simulator, which treats nonlinear gas flow rigorously and accurately to simulate rate-transient data, is used. Both synthetic noise-free and noisy-rate pressure-data sets considering wide ranges of initial reservoir pressure and BHP, as well as real-field data sets, are used to compare the methods. For linear flow, the Nobakht-Clarkson method (Nobakht and Clarkson 2012a, 2012b) yields the best results, although its use is tedious because it requires an iterative procedure. The Chen and Raghavan (2013) method for linear flow seems to provide results that are comparable with the Nobakht-Clarkson method (Nobakht and Clarkson 2012b) but does not require an iterative procedure. The Ibrahim-Wattenbarger method (Ibrahim and Wattenbarger 2006) for linear-flow analysis always overestimates flow capacity compared with the other methods. Among the methods that discuss the ending time of linear flow, it was found that the unit-impulse method from Behmanesh et al. (2015) provides the best results for predicting gas in place. For BDF, the results show that the Agarwal-Gardner FMB method (Agarwal et al. 1999) is quite vulnerable to the error in rate/pressure data, whereas the conventional FMB method is more robust to noise and provides more accurate estimates of gas in place.

Effect of Gas Adsorption on the Estimation of Gas in Place (GIP) in Conventional and Unconventional Reservoirs

The estimation of the gas in place (GIP) in conventional and unconventional reservoirs is crucial for the gas industry. Further development in gas fields depends on the gas stored in the underground reservoirs. Several methods are used to determine the GIP, such as material balance calculations or decline curve analysis. If the gas adsorption effect is considered and well modeled using Langmuir isotherm, for instance, for the unconventional reservoirs, it is not the case for the conventional ones. In this study, several adsorption experiments using methane were conducted on intact conventional and unconventional rocks at high pressure and high temperature. Conventional calcite rock samples of high permeability (around 100 mD) and tight sandstone rocks of low permeability (around 0.1 mD) were used to determine the gas adsorption. Tight sandstone rocks of low permeability (around 0.1 mD) were tested for gas adsorption. Finally, unconventional shales rocks were tested for adsorption experiments as well. The adsorption isotherms were developed for all rocks, and these isotherms were used to correct the estimation of the GIP. The results of this study showed that conventional carbonate rocks can adsorb considerable amount of gas. This adsorbed gas was not taken into account in the previous estimations of the GIP. The adsorbed gas can add up to 10% of the GIP. In addition, Langmuir isotherm was not the right fit for all experiments for the different rock samples tested in this study. BET and Freundlich models were the best fit for all experiments that consider multilayer adsorption. Including BET or Freundlich models in both conventional and unconventional rocks will enhance the estimation of the GIP and further field development plans.

Construction of a 3D Geomechanical Model for Development of a Shale Gas Reservoir in the Sichuan Basin

SummaryCurrently, there is large-scale shale gas exploration and development in the Sichuan Basin, western China. Caused by high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan Basin has encountered many difficulties, such as placing sufficient proppant, poor-production performance for some wells, and ambiguity as to the factors controlling the production of reservoirs. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs is a major obstacle to effectively addressing these difficulties.A 3D full-field geomechanics model was constructed for the Changning shale gas reservoir in the Sichuan Basin through integrating seismic, geological structure, log, and core data by following a newly formulated work flow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. The 3D pore-pressure prediction was conducted with seismic data, and calibrated against pressure measurements, mud-logging data, and flowback data. A discrete-fracture-network (DFN) model, which represents multiscale natural-fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural-fracture systems.The 3D pore-pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir, and explains how the 3D geomechanical model is used to address technical challenges encountered during drilling and completion. Also, it demonstrates that a reliable 3D geomechanical model, with proper characterization of anisotropy, pore pressure, and natural fractures, provides a critical opportunity to improve the development in this shale gas reservoir.

Analysis of multi-layered commingled and compartmentalized gas reservoirs

The evaluation and performance prediction of multi-layered compartmentalized gas systems can be difficult. This is mostly due to the uncertainties related to production allocation either within each commingled well or between interrelated reservoir compartments. This paper presents a model that can provide reliable estimates of the total gas in place for multi-layered commingled and compartmentalized reservoirs. The model is also capable of generating prediction profiles for every well in the production system in addition to forecasting individual layers production for each compartment. The proposed model is based on coupling the layered stabilized flow model for material balance calculation in commingled systems with communicating reservoir model that is used as material balance tool for compartmentalized gas reservoirs. The model has the flexibility to be applied for history matching and prediction purposes. In history matching, the model solves the equations simultaneously using optimization routine to find the best parameters of original gas in place (OGIP), deliverability coefficients and compartment transmissibility coefficients. The model requires the knowledge of initial reservoir pressure in every compartment, some rate production history and bottom-hole flowing pressures. The model can also utilize additional information such as shut-in pressures per layer, repeat formation tester and production logging tool measurements (if available) to improve the history match. For prediction, the model uses the estimated parameters (compartment OGIP, transmissibility coefficients between compartments and flow parameters for each layer) to calculate the production rates and reservoir pressures for every well/tank based on a provided bottom-hole flowing pressure. The model was verified against a commercial reservoir simulator for several synthetic cases. The model was also applied on different field cases to estimate OGIP and flow coefficients for every layer as well as compartment transmissibility coefficients. Moreover, calculation of cumulative gas transferred across the communicating reservoirs allows detection of poorly drained compartments, which could be included in future redevelopment plans.

Technology Focus: Seismic Applications (March 2016)

Technology Focus From time to time, I am asked to address general audiences. The mission is to describe what we do in the seismic business. Typically, the first slide I show is a prenatal ultrasound display of my daughter. I explain that using reflected sound waves to create such an image is precisely what we do with the Earth. The world’s first reflection seismic field tests were conducted near Oklahoma City in 1921, and, ever since then, the industry has endeavored to improve that seismic imaging process. So, indeed, one of the papers selected for this Technology Focus section and one of the papers recommended for additional reading deal with case histories in which imaging is improved through better velocity-model building. In the first paper, integration of microgravity data, resistivity measurements, and seismic is the key in the onshore case history from Qatar. In the first additional-reading paper, full-waveform inversion of seismic travel times and amplitudes is the key in the case history from offshore Australia. Advances in seismic applications are not just confined to imaging, though. In another additional-reading paper, amplitudes are used for identifying porous zones in an otherwise tight-sandstone gas reservoir in Oman. And, in the third additional-reading paper, the authors use the amplitudes in 4D analyses for identifying new reservoir drive mechanisms in a field offshore Brunei. Both imaging and amplitude inversion benefit greatly from broader-band data. Therefore, this is the topic of the second paper presented. In this example from offshore Malaysia, the marriage of a new acquisition technique with new processing algorithms yields broader frequency content, enabling more-accurate estimates of gas in place to be derived. But even further advances in seismic applications are taking place now, especially in the world of unconventional resources. The authors of the third selected paper discuss the integration of miscroseismic data with 3D-seismic attributes, well-log data, and completion data to understand the geomechanical rock properties in the Midland basin of Texas. This information was important for planning the spacing of new wells. I hope this journey is successful in showing that substantial advances continue to be made globally in seismic applications. But, perhaps even more importantly, I hope the journey shows that some of the more exciting advances are actually arising from the integration of seismic with other technologies and that, while imaging may still be king in seismic (and in some fields of medicine), the applications of seismic to building 3D mechanical Earth models, for example, are gaining prominence. JPT Recommended additional reading at OnePetro: www.onepetro.org. IPTC 17905 High-Resolution Anisotropic Earth-Model Building on Conventional Seismic Data Using Full-Waveform Inversion: A Case Study Offshore Australia by Bee Jik Lim, Schlumberger, et al. SPE 177552 Seismic Reservoir-Quality Prediction, Khazzan Field, Oman by T. Chris Stiteler, BP, et al. IPTC 18491 4D Seismic in Stacked Reservoirs—From Puzzles to Insights on Production Drive Mechanisms by Denis Kiyashchenko, BSP, et al.

Identifying sweet spots and moving CBM reservoirs into production

C oalbed methane (CBM) is well recognised as an important natural gas resource. However, producing it commercially has proven to be a challenging process, primarily due to the complex nature of its gas storage and flow mechanisms. Although CBM reservoirs are naturally fractured due to the presence of face and butt cleats, gas stor­age and saturation depend on the adsorption capacity of the coal matrix. The ability to predict permeability variations and its evolu­tion in a CBM reservoir, which is affected by several dynamic CBM properties and operating conditions, also define the design, optimization, and analysis of the gas recovery process. As the permeability is naturally low, interventions are necessary in order to achieve commercially viable gas production rates. CBM are also dual-porosity media where the vast majority of the gas is stored in the low permeability coal matrix by sorp­tion. The flow to production wells, however, occurs through the coal’s natural fracture system, that stores relatively small amounts of gas, because coal matrix practically has no perme­ability. The result is that properties of the coal matrix have the greatest effect on the estimates of gas in place and recovery. It is well understood that the key parameter controlling gas flow in CBM reservoirs are cleat networks, gas storage, desorp­tion and permeability anisotropy (coal shrinkage and swelling). While the role of reservoir simulation is well under­stood for conventional oil and gas reservoirs and its related techniques for prediction and production optimisation, for unconventional reservoirs (CBM, Shale, etc.) current reservoir simulation software needs to be further developed and adapted to represent the performance of these types of fields and gener­ate more acceptable results. For example, the basic governing fluid flow regime in conventional reservoir simulations is limited to Darcy flow. For unconventional reservoirs, however, another flow regime term comes into the equation that reflects the flow of gas in the coal matrix and stands for diffusion. This new flow regime is not very well defined in the current simulators and needs further studies to appropriately address the production performance of a reservoir. Furthermore, the concept of multi-phase flow in reservoirs is well defined by the introduction of relative permeability equations in the flow equations. However, measuring relative permeability in coal is relatively complex (Ham and Kantas, 2008) due to its friability, heterogeneity, stress dependence and porous morphology. Young et al. (1992), for example, noticed that the derived relative permeability from a history match does not resemble the laboratory measurement. This phenomenon could be due to the change of matrix structure on phase flow in addition to wettability and capil­larity. In other words, both phases may flow through different passages over time due to heterogeneity. Thus dynamic rela­tive permeability (phase saturation) is required to accurately predict recovery from a CBM reservoir. As the focus on CBM has increased in the past decades, so has the quest for more effective technologies to help bring the reserves in such complicated conditions into production and to identify sweet spots. Reservoir modelling and reservoir simulation are technologies that are likely to play a key role in achieving this. Firstly, however, it is necessary to look at the challenges of CBM property variations.

New Estimation Technique Shifts Assessment of Global Unconventional Gas Resources

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 148365, ’Global Unconventional Gas Resource Assessment,’ by Z. Dong, S.A. Holditch, SPE, D.A. McVay, SPE, and W.B. Ayers, SPE, Texas A&amp;M University, prepared for the 2011 SPE Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed. As the world reserves of liquid hydrocarbons from conventional reservoirs peak and begin to decline, natural gas will play an increasingly important energy supply role. Most estimates of the original gas in place (OGIP) reported for world unconventional gas start with Hans-Holger Rogner’s 1997 top-down study. That global estimate is most likely quite conservative because the oil and gas industry has discovered enormous volumes of shale gas around the world since the 1990s. The objective of this project was to estimate the probabilistic distributions of original volumes of gas trapped in coalbed, tight sand, and shale reservoirs worldwide. Introduction To accomplish this objective, the authors reviewed published assessments of coal and conventional and unconventional resources and established the quantitative relationship between unconventional gas [coalbed methane (CBM), tight sands gas, and shale gas] and the conventional hydro-carbon (coal, conventional gas, and oil) resource endowments for North America. Then, they used this relationship to extrapolate original unconventional gas in place worldwide. For the assessments, P10, P50, and P90 are the values for which the probability is 10, 50, and 90%, respectively, that the value will be exceeded. This work established an unconventional OGIP of 83,400 Tcf (P90)–184,200 Tcf (P10), which is 2.6–5.7 times greater than Rogner’s estimate of approximately 32,600 Tcf. Global Unconventional Gas Base. According to Rogner’s estimates, world-wide original in-place resources were approximately 9,000 Tcf of CBM, 16,000 Tcf of shale gas, and 7,400 Tcf of tight sands gas. Rogner’s 1997 global estimate is most likely quite conservative, given the recent discovery of significant shale gas around the world. Resource Triangle. J.A. Masters suggested in a 1979 paper that hydrocarbon resource types can be assigned to various resource classes in a triangular distribution and that their positions in the triangle reflect their abundance, their reservoir quality, and the technology required for recovery (Fig. 1). As one goes lower on the gas resource triangle, the reservoirs are lower grade, which usually means the reservoir permeability is decreasing. These low- permeability reservoirs are much larger than the higher-quality reservoirs.

Practical Aspects of Reserves Determinations for Shale-Gas Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144357, ’Practical Aspects of Reserves Determinations for Shale Gas,’ by R. Strickland, SPE, D. Purvis, SPE, The Strickland Group, and T. Blasingame, SPE, Texas A&amp;M University, prepared for the 2011 SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 12-16 June. The paper has not been peer reviewed. Uncertainty in shale-gas reserves has significant implications at both the micro and the macro level. Conventional reservoir-engineering tools must be viewed as potentially inadequate (or even inappropriate) for evaluating shale-gas performance, primarily because of the extremely low aggregate permeability of these systems. Methods for shale-gas evaluation are discussed (including methods and limitations) that represent the physics of shale-gas production more closely; however, their implementation often is prohibitive. Introduction Although some 20,000 horizontal shale wells have been drilled, the longest production history available is approximately 6 years. To complicate matters further, the nature of shale development creates an urgent need for accurate predictions of recovery very early in the life of a play. The industry’s ability to interpret well logs, analyze core, and understand (at least qualitatively) the geological controls on production has increased vastly and has proved to be more important than acknowledged previously. Those geological factors are more numerous and more complexly interrelated than for conventional reservoirs. Engineering Methods Depending upon how the methods are grouped, there are six basic engineering techniques for determining reserves in general: volumetrics, analogy, production performance, material balance, simulation, and, most recently, rate-transient analysis (RTA). Each method has its own predicates and limitations. In the case of shale gas, they also have their own idiosyncrasies for accurate application. Material balance is not suitable because the ultralow matrix permeability makes obtaining average reservoir pressure impractical. With volumetrics, improvements in core and petrophysical analyses have led to reasonable estimates of gas in place; however, the recovery factor to be applied to an in-place figure is imprecise at best. The many difficulties caused engineers to rely heavily on the simplest, most accessible tool: production-decline analysis. Often, very large asset purchases or even entire plays have been reduced to a single type curve on the basis of production performance. This fact concentrates and, thus, amplifies potential error. Without the benefit of good analogs or sufficient guidance from first principles, it is possible, even likely, that production analysis results in a carelessly optimistic view of ultimate recovery. Fortunately, concentrated effort by many engineers and academics has significantly advanced the understanding of, and analysis tools for, shale gas. Simulation, RTA, and decline-analysis methods have demonstrated usefulness in shale-gas reservoirs, but they must be applied in a manner consistent with the uniquenesses of shale reservoirs.

Coalbed Methane: Current Field-Based Evaluation Methods

SummaryCoalbed methane (CBM) produced from subsurface coal deposits has been produced commercially for more than 30 years in North America, and relatively recently in Australia, China, and India. Historical challenges to predicting CBM-well performance and long-term production have included accurate estimation of gas in place (including quantification of in-situ sorbed gas storage); estimation of initial fluid saturations (in saturated reservoirs) and mobile water in place; estimation of the degree of undersaturation (undersaturated coals produce mainly water above desorption pressure); estimation of initial absolute permeability (system); selection of appropriate relative permeability curves; estimation of absolute-permeability changes as a function of depletion; prediction of produced-gas composition changes as a function of depletion; accounting for multilayer behavior; and accurate prediction of cavity or hydraulic-fracture properties. These challenges have primarily been a result of the unique reservoir properties of CBM. Much progress has been made in the past decade to evaluate fundamental properties of coal reservoirs, but obtaining accurate estimates of some basic reservoir and geomechanical properties remains challenging.The purpose of the current work is to review the state of the art in field-based techniques for CBM reservoir-property and stimulation-efficiency evaluation. Advances in production and pressure-transient analysis, gas-content determination, and material-balance methods made in the past 2 decades will be summarized. The impact of these new methods on the evaluation of key reservoir properties, such as absolute/relative permeability and gas content/gas in place, as well as completion/stimulation properties will be discussed. Recommendations on key surveillance data to assist with field-based evaluation of CBM, along with insight into practical usage of these data, will be provided.

Determining Effective Drainage Area for Tight Gas Wells

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98035, "Determination of Effective Drainage Area for Tight Gas Wells," by S.A. Cox, R.P. Sutton, and R.P. Stoltz, Marathon Oil Co., and T. Knobloch, James Engineering Inc., prepared for the 2005 SPE Eastern Regional Meeting, Morgantown, WV, 14–16 September. The effective drainage area of a tight gas well is controlled primarily by rock and fluid properties, reservoir geometry, and well-completion efficiency. This work focused on the relationship between effective gas permeability, porosity, reservoir geometry, and fracture half-length for dry-gas reservoirs. Introduction The effective drainage area of tight gas reservoirs can be determined best with production analysis. Two methods of determining the effective area for dry-gas reservoirs were studied. In tight gas reservoirs (reservoirs with effective gas permeability less than 0.1 md), a significant amount of time is required before the pressure transient is affected by all of the boundaries of the reservoir. The no-flow boundaries affecting the well's pressure-transient behavior can be physical or caused by offset production. Therefore, the effective drainage area of a tight gas producer will be a function of natural boundaries, drilled-well spacing, effective gas permeability, and completion efficiency. The efficient well spacing for tight gas producers can be defined in many ways. For the purpose of this paper, efficient spacing is the well spacing required to attain 80% recovery of the gas in place over a 30-year life. An alternative definition was the well spacing required to maximize the well's 30-year recovery. However, these cases resulted in very low recovery of the in-place volume. For the same reservoir geometry, efficient well spacing increases with both permeability and fracture half-length. This work demonstrated that as a system becomes more linear in nature, the effective drainage area is reduced for the same reservoir and completion parameters. Background Determining the effective drainage area of a producing well was accomplished by first estimating the well's drainage volume. Then, this volume was used in the volumetric equation to estimate the well's drainage area. Both methods described below combine gas-material-balance and flow equations to estimate the well's effective drainage volume. The assumptions common to both methods are as follows.Well production rates and pressures are accurate.The flowing bottomhole pressure can be estimated accurately from surface pressures, if not measured.The reservoir drive mechanism is volumetric depletion. The full-length paper details both methods. El-Banbi and Wattenbarger Method This method combines gas-material-balance and stabilized-flow equations for gas wells into an iterative method that can be used to estimate the drainage volume of a well during boundary-dominated flow (BDF). Results then can be combined with the reservoir properties in the volumetric equation to estimate the well's effective drainage area. To perform the analysis, an initial-gas-in-place value is assumed, and the real-gas-pseudo pressure function is calculated and plotted vs. time. If the assumed in-place volume is too large, the plot will have a positive slope at late time. If the assumed volume is too small, the slope will be negative. The correct estimate of gas in place will result in a late-time slope of zero. If the system is evaluated during transient flow, the effective drainage area will be under-estimated and will increase through time. Once boundary-dominated flow is achieved, this method will predict the well's drainage volume accurately.

Resource-assessment perspectives for unconventional gas systems

Concepts are described for assessing those unconventional gas sys tems that can also be defined as continuous accumulations. Contin uous gas accumulations exist more or less independently of the wa ter column and do not owe their existence directly to the buoyancy of gas in water. They cannot be represented in terms of individual, countable fields or pools delineated by downdip water contacts. For these reasons, traditional resource-assessment methods based on es timating the sizes and numbers of undiscovered discrete fields can not be applied to continuous accumulations. Specialized assessment methods are required. Unconventional gas systems that are also continuous accumu lations include coalbed methane, basin-centered gas, so-called tight gas, fractured shale (and chalk) gas, and gas hydrates. Deep-basin and bacterial gas systems may or may not be continuous accumu lations, depending on their geologic setting. Two basic resource-assessment approaches have been em ployed for continuous accumulations. The first approach is based on estimates of gas in place. A volumetric estimate of total gas in place is commonly coupled with an overall recovery factor to nar row the assessment scope from a treatment of gas volumes residing in sedimentary strata to a prediction of potential additions to re serves. The second approach is based on the production perfor mance of continuous gas reservoirs, as shown empirically by wells and reservoir-simulation models. In these methods, production characteristics (as opposed to gas in place) are the foundation for forecasts of potential additions to reserves.

Influence of Water on Estimation of Gas in Place

Summary The usual method for determining the gas in place (GIP) in a reservoir uses a balance equation based on laboratory measurements of the raw gas volumetric factor as a function of pressure on a water-free basis. In the reservoir, however, the gas is saturated with water. Volumetric measurements at high temperatures and pressures have been performed on a North Sea fluid at 374°F, both in water-free conditions and in the presence of an excess water. The water content of the gas at 650 bar has been determined to be 3.5 mol% (3.6 mole of water/100 mole of reservoir fluid) water-saturated reservoir fluid. A corresponding volume increase of 3.2 % has been detected. These experimental measurements have been correlated with a Tait-type equation. The S0reide and Whitson1 model has been used to calculate the water content of the gas. A modified balance equation is proposed for prediction of the GIP.

Geologic Controls on the Occurrence of Methane in Coal Beds of the Pennsylvanian Hartshorne Formation, Arkoma Basin, Oklahoma

Hartshorne coals have long been known to be extremely gassy because early underground mines in the Arkoma basin were plagued by methane. Mine data, combined with recent advances in coal-bed methane technology, allow us to better quantify this gas resource. The gas content of Hartshorne coals is controlled by a number of factors, including thickness, thermal maturity, as content, and reservoir pressure. Hartshorne coal can be generally characterized as being thin (<6 ft), of relatively high thermal maturity (R[sub O] 0.7 to 1.7), and of relatively low ash content (<10%). Very little pressure data are available for the Hartshorne, but it appears that Hartshorne coals are underpressured to normally pressured with no indication of overpressuring. Estimates of gas in place for Hartshorne coal range from 2 to 6 bcf of gas per 640 ac. Primary controls on the producibility of methane from the Hartshorne include the hydrology of the coal, and its permeability. Conflicting data exist as to the nature of the hydrologic regime of the coal. The existence of dry coal in a variety of structural setting is well established. Free-water production from the coal, where present, tends to be low volume (<10 bbl/day) and of a brackish chloridemore » composition. Permeability is controlled by a number of factors, including cleat intensity and tectonic fracturing. Locally diagenetic cements may significantly reduce permeability.« less

New Core Analysis Methods for Measuring Reservoir Rock Properties of Devonian Shale

Summary We developed a new method involving crushed core samples to measure porosityand fluid content accurately in the black, organic-rich Devonian shales in the Appalachian basin. In the four wells studied, average core bulk volume of gasand porosity ranged to 4% and 8%, respectively, values substantially higherthan previously reported. previously reported. Introduction The Devonian shale in the Appalachian basin is considered a major potentialgas source. Because of analytical difficulties, core potential gas source. Because of analytical difficulties, core analysis in shales for reservoirproperties is not done often. Previous reports 1-3 show typical core porositiesof 2% to 3% in Previous reports 1-3 show typical core porosities of 2% to 3% inthe Devonian shale and free-gas content less than 0.1 % to 0.2 % by bulkvolume. Estimates of gas in place associated with these low free-gas contentsare an order of magnitude lower than is customarily produced in Devonian shalewells with long-term production history. produced in Devonian shale wells withlong-term production history. The goal of this study, sponsored by the Gas Research Inst. (GRI), was to improve our understanding of formation evaluationand reservoir description in shales. Four wells have been air-drilled recentlyin Kentucky and West Virginia from which extensive formation evaluation data, including 519 ft of conventional cores in the Devonian shale, have beencollected (Fig. !). Core recovery by formation is shown for each well in Table1 (the wells were drilled in the sequence shown). These wells were designatedcomprehensive study wells (CSW's) because of the extensive GRI- fundedevaluation-data program. One purpose of the CSW program was to develop newformation evaluation methods to identify gas-producing intervals, for bothdeliverability and reserves, with logging tools. Significant progress has beenmade. A key element of these new is to progress has been made. A key element ofthese new is to establish the reservoir rock and fluid properties throughcareful core analysis and then to develop the log interpretation methodsnecessary to match core analysis and production results. In the four CSW'S, cores range from shaly siltstones and laminated siltstones and shales to siltyshales. Mean grain size ranges from 0.01 to 0.06 mm. Mineralogy and petrographyshow the shale to be predominantly quartz and illite, with other mineralsincluding pyrite and kerogen (which can range up to 30 vol %). In CSW No. 2, the first well cored in the CSW program, very little kerogen and oil werepresent. Core analyses were similar to those in other low-permeabilitygas-productive reservoirs: water content was determined by weight loss afterextended drying in a convection oven at 230F, which removes both free andclaybound water. We measured grain volume of the dry core with helium and bulkvolume by immersing the core in mercury. PV is the difference between bulk andgrain volume. Free-gas content is the difference between PV and water content. These measurements were made at 1-ft intervals from the cored interval. Becausethese cores, and those from CSW Nos. 4A, 5, and 1A, were drilled in air-mistand the cores were preserved at the wellsite, the fluid saturations in the coreshould represent those in the reservoir after appropriate correction forcompaction to reservoir stress. When core analyses were begun on the next well, CSW No. 4A, different methods were required because the cores containsignificant amounts of oil and kerogen. Initially, core pieces were extractedin boiling toluene with the Dean Stark method for up to 2 weeks; the cores weredried in a convection oven at 230F for about 2 weeks; and PV's were determinedwith helium. This resulted in grain densities and porosities that were much toolow compared with log analyses. A new method of core analysis was developedthat involves crushing the core to speed up the processes of extraction, drying, and grain volume measurement. This new method results in much higherporosity and gas content values in the shale samples from CSW No. 4A, whereboth methods were used. The following sections describe the new core analysismethods. Porosity results are shown by a comparison of the new methods to Porosity results are shown by a comparison of the new methods to conventionalanalyses in normal-permeability rocks and in cores from the kerogen-free CSWNo. 2 to verify the new methods. Porosity and fluid content are shown fromcompanion sets of 95 crushed samples run by two separate laboratories toillustrate repeatability. Core analysis results are compared with a loganalysis in one of the study wells. Core analysis results for all four studywells are summarized. Finally, examples of other applications of analyses ofthe companion crushed sample sets are shown. P. 1184

A SEISMIC AMPLITUDE VERSUS OFFSET STUDY IN THE SOLE AREA, GIPPSLAND BASIN

Analysis of amplitude versus offset (AVO) variations in shallow reservoirs can be a powerful tool, and has been used to determine the nature and distribution of hydrocarbons in the Sole area.The Sole-1 well was drilled in 1973 on the northern margin of the Gippsland Basin. The well encountered a 16 m dry gas column at the top of the Latrobe Group, within a fault-bounded anticline.Seismic line GS88B-97 was acquired in 1988 over the crest of the Sole Anticline. A dipping reflection event cross-cutting the geological structure was interpreted as a reflection emanating from the base of the gas column. Structural interpretation is ambiguous at the field's northern bounding fault and potential was recognised for a significant extension of the field northwards.An AVO study comparing variations in measured reflection amplitudes on common depth point (CDP) gathers and substacks with modelled results has been successful in unambiguously delineating the field extent and shows that the field is bounded to the north by the main fault. This successful use of AVO techniques at Sole has permitted a more precise estimate of gas in place and has potential for application to other accumulations along the northern margin of the Gippsland Basin.

A Coal Bed Methane Resource Estimation of the Alberta Basin

Alberta contains approximately 6000 gigatonnes of coal ranking from subbituminous to low-volatile bituminous. The authors calculations show the amount of coal bed gas potentially in place is in the order of 73.5 {times} 10{sup 12} m{sup 3} (2.6 {times} 10{sup 15} ft{sup 3}). This is an enormous resource that is being updated continuously as new data become available. Estimates of the maximum coal gas in place for the United States are about 4 {times} 10{sup 14} ft{sup 3}. In the Alberta portion of the Western Canada Sedimentary basin the coals are distributed throughout the foothills and plains regions and range from Jurassic to Tertiary in age. The potential that these coals may generate sufficient gas to be considered a significant commercial fuel source has only been realized in the last several years. Because of the relative infancy of this resource development in Alberta, only limited direct data are available. The coals in Alberta have not been extensively tested for gas content. However, the evaluation of coal bed methane resources are possible through the use of indirect data such as thickness, rank, and depth, as well as proximate analysis to obtain an estimate of the gas content. This paper reviews themore » formations and geographic areas of gas potential and the reasoning used to derive the coal and gas content resource estimates.« less

Case History of the Meillon Gas Field

Summary This paper presents results of studies performed to determine how waterinvasion in tight, fractured carbonate formations governs gas productivity. Seismic and dipmeter data were used to create a new structural picture of theMeillon field. Although the wells located at the top of the structure areinvaded by water, we concluded that the field was not totally invaded, but waslocally invaded. As a result, new wells are being drilled, compressors arebeing installed to increase production, and water is pumped out. production, and water is pumped out. Introduction Meillon gas field was discovered in 1965 with the Meillon 1. It is locatedin southwestern France near the Lacq gas field. The east/west reservoir is 17miles [27 km] long, 2 miles [3 km] wide, and 14,760 ft [4500 m] subsea. Part ofit is below the town of Pau. Original sour gas in place was evaluated to beappx. 2,650 × 109 scf [appx. 75 × 109 std m]. Many wells were drilled in the area, but acquiring a good understanding ofthe reservoir's structural features was difficult because it is highlydislocated. For 10 years gas production was waterfree; it was thought that the reservoircould be depleted with the 10 existing wells (two clusters) located at the topof the structure near the fault. In 1978, cumulative production was 918 × 109scf [26 × 109 std m] production was 918 × 109 scf [26 × 109 std m] when wellslocated 2,300 ft [700 m] above the initial gas/water contact (GWC) started toproduce water. Five new wells were drilled along the structure between 1978 and1986 as older wells stopped producing because of water-lift problems. Actualcumulative production was 1,520 × 109 scf [43 × 109 std m]. A structural study performed to understand the water entry showed that openfractures are oriented in an east/west direction, especially along the southernfaulted area. This finding completely changed our understanding of the dynamicreservoir behavior. A numerical simulator that accounted for a permeability contrast in theeast/west and north/south directions was used to match the production historyduring the water-free production history during the water-free period. period. This paper describes the hypotheses derived from these observations and thepractical actions implemented. practical actions implemented. FieldDescription Structure and Geology. Field development was impaired by stratigraphiccomplexity and difficulty in seismic interpretation. The reservoir, located inthe Jurassic formation, is an anticline structure with three main communicatingareas, Baysere and Pont d'As, St. Faust, and Mazeres (Fig. 1). The northernflank dips 20 to 30 deg. north; the southern flank is reduced by anunconformity and a major east/west fault (Fig. 2). The reservoir is 660 to 820ft [200 to 250 m] thick, and the initial GWC is located at 16,275 ft [4960 m]subsea. (This was deduced from pressure measurements in Wells Lons 1 in theaquifer and Meillon 1 in the gas phase.) Reservoir Characteristics. The reservoir is a low-porosity (vugular in someareas), low-permeability dolomite, with a porosity ranging from 1 to 8%, and amatrix permeability less than 1 md. Two to three fractured zones are randomlylocated over each well. Reservoir Contents. The reservoir contains sour gas underlain by water. Thegas column reaches a maximum of 2,800 ft [850 m] at the crest of the structure,13,450 ft [4100 m] subsea. Table 1 presents the gas composition. Initialpressure at 13,450 ft [4100 m] is 6,960 psi [48 MPa], and temperature is 300deg. F [150-C]. Volumetric Estimate of Gas in Place. The volumetric evaluations are fairlyinaccurate because of the important uncertainties in all parameters (e.g., structural and petrophysical parameters (e.g., structural and petrophysicaldata). Initial gas-in-place estimates ranged from 2.3 × 1012 to 3.53 × 1012 scf[65 × 109 to 100 × 109 std m]. Field Development and History Field Development. Gas production started in Oct. 1968, with three wells(Baysere 1, Pont d'As 1, and Pont d'As 2) located at the Pont d'As 1, and Pontd'As 2) located at the west end of the structure. Some wells (Pont d'As 3 and4; St. Faust 2 through 5, 7, and 2; and Baysere 2) were drilled eastward in thewestern half of the reservoir until the end of 1971. All wells were located on the crest of the structure, and the field wasinitially developed with two well clusters. Some wells started producing waterin 1978, and field productivity declined dramatically (Fig. 3). productivitydeclined dramatically (Fig. 3). The eastern part of the reservoir becameisolated, and the pressure profile from west to east showed a pressure sinkthat was created in the center of the reservoir, where well concentration washighest (Fig. 1). P. 1032

An Analysis of the Coal-Seam Gas Resource of the Piceance Basin, Colorado

Summary A detailed geologic analysis of the Piceance basin in northwestern Colorado shows that nearly 84 Tcf [2.4 × 10 M] of coal-seam gas is in place in three target coal groups. The Cameo coal group contains the most coalbed methane with 65 Tcf [1.8 X 10 M ]. The more areally limited Coal Ridge and Black Diamond coal groups contain significantly less gas, 10 and 9 Tcf [280 × 10 and 255 × 10 M], respectively. The areas of highest methane concentration are in the east-central portion of the Piceance basin. These areas coincide with thick deposits of high-rank coals at significant depths and their associated higher gas contents. Also, these areas appear to have been structurally (tectonically) altered, leading to enhanced permeability to gas and water. Thus, the east-central basin area appears favorable for coalbed methane production. This study relied on extensive well data to correlate and map the subsurface extent of the Cretaceous coals of the Piceance basin. Newly derived correlations of coal-rank/depth with gas content were used along with estimates of coal volume to determine gas in place. Introduction Coal-seam gas-natural gas that has evolved from and is adsorbed by coal seams-is a major potential source of domestic natural gas, The majority of this resource is contained in 13 coal basins distributed broadly across the U.S. (Fig. 1). The Piceance basin, located in northwestern Colorado, is documented as one of the gassiest coal regions in the U.S. Currently, the basin is the site of the Gas Research Inst. (GRI) Deep Coal Seam Research Project and, at the end of 1985, contained 32 wells drilled specifically for coalbed methane extraction. A detailed understanding of the regional distribution of the geologic parameters controlling coal-seam gas accumulation and flow is a key factor for economical gas recovery. This paper presents the results of a detailed subsurface geologic analysis of the three major Piceance basin coal groups-the Black Diamond, Cameo, and Coal Ridge of the Iles and Williams Fork formations of the Mesaverde group. From extensive well data, the lateral and vertical extent of the Late Cretaceous Age coals were delineated to estimate coal volumes. These estimates were combined with newly derived correlations of coal-rank/depth with gas content to calculate gas in place for the basin's three major coal groups. The geologic analysis and resource estimate of the Piceance basin coals were sponsored by GRI's Natural Gas Supply Program. The analysis was undertaken as part of a larger resource economics study to determine the economically recoverable natural gas from U.S. coal basins, particularly with advanced extraction technologies. Study Methodology The estimate of coal-seam gas in place for the Piceance basin relied on a basic geologic evaluation of the subsurface geometry of the basin's three major coal groups. The two foundations of the Piceance basin geologic analysis are the regional cross sections correlating coal groups across the basin and the stratigraphic data from 190 well logs.

Some Petroleum Engineering Considerations in the Changeover of the Rough Gas Field to the Storage Mode

This article presents a reservoir engineering case history of the Rough field development. The role of the field in the supply/demand match is described and the reliability and production requirements are given. The modeling of surface facilities in the development of an overall scheme for a gas storage field is outlined. Finiteelement reservoir modeling techniques are used. The main results of the reservoir simulation are presented and include the field production/injection profile.